ML18037A629
| ML18037A629 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 12/09/1993 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18037A627 | List: |
| References | |
| 50-259-93-39, 50-260-93-39, 50-296-93-39, NUDOCS 9401040132 | |
| Download: ML18037A629 (37) | |
See also: IR 05000259/1993039
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 30323-0199
Report Nos.:
50-259/93-39,
50-260/93-39,
and 50-296/93-39
Licensee:
Valley Authority
6N 38A Lookout Place
1101 Harket Street
Chattanooga,
TN
37402-2801
Docket Nos.:
50-259,
50-260,
and 50-296
License Nos.:
and DPR-68
Facility Name:
Browns Ferry Units 1, 2,
and
3
Inspection at Browns Ferry Site near Decatur,
Inspection
Conducted:
October
16 November
19,
1993
r
0
Inspector:
> r
ess
n
nspector
z,
v
ate
sgne
Accompanied
by:
J.
Hunday,
Resident
Inspector
R. Husser,
Resident
Inspector
G. Schnebli,
Resident
Inspector
L. Watson,
Project Engineer
Approved by:
a
.
e
Re ctor
c s, Section
4A
Division of R actor Projects
SUHHARY
a e
1gne
Scope:
This routine resident
inspection
included surveillance
observation,
maintenance
observation,
operational
safety
verification, design
changes
and plant modifications, Unit 3
restart activities, reportable
occurrences,
action
on previous
inspection findings, site organization,
and independent
safety
engineering
'group.
One hour of backshift coverage
was routinely worked during the
work week.
Deep backshift inspections
were conducted
on October
17,
30 and
November 7,
14,
18,
and
19,
1993.
9401040i32
931217
ADOCK 05000259
8
Unit two operated
continuously during this period
and was on-line
for 169 days at the 'end of the period,
paragraph
4.
A plant trip
was possibly avoided during work on the condensate
demineralizers
due to a design
change
made under the scram frequency reduction
. program.
The change modified the timing of the feed
pump
and feed
booster
pump suction trips.
Efforts such
as this have contributed
to the continuous
run time of the unit.
One violation with two examples for failure to control design
changes
was identified by an
NRC inspector,
paragraphs
5 and 6.
The first example
was for failure to adequately
review a design
change after control
room drawings were issued to reflect
identification number changes
for fuses,
handswitches,
and other.
components.
Plant operating instructions
and labeling were not
changed to agree with the drawings.
Although, the problem was
identified on system 31, air-conditioning system,
the problem is
applicable to several
other systems
being renumbered.
The
licensee's
quality assessment
of fuse labeling
came to an
erroneous
conclusion that labeling was adequate.-
The second
example involved failure to adequately
control coordination of a
design
change that modified the unit separation
boundary but the
required configuration boundaries
were not modified.
These
examples
are indication of a programmatic
problem with the
coordination of design
changes
between
engineering,
operations,
technical
support,
and other groups.
An unresolved
item was identified by an
NRC inspector for an
potentially inadequate
safe
shutdown procedure revision,
paragraph
4.
The licensee
on November 3,
1993,
made
112 changes
to the fire
protection safe
shutdown
equipment
compensatory
measures.
This
plan was approved
by the
NRC April 1,
1993.
These
changes
were
made without Commission
approval
although there is
a potential to
adversely affect the ability to achieve
and maintain safe
shutdown
in the event of a fire.
Characteristic
of these
changes
was
revising
a requirement to isolate the reactor water cleanup
system,
based
on controlling the loss of water inventory, .to
permitting the establishment
of a fire watch after seven
days.
The licensee
made these
changes after electrical
cables to the
system isolation valves were identified as
being routed through the
same fire zone.
An inspector followup item was identified by an
NRC inspector
concerning
acceptance
criteria for the analog trip units,
paragraph
4.
There is no limit specified for the difference
between
main steam line flow differential pressure
readings.
An unresolved
item was identified by an-NRC inspector
concerning
the observation of an unfinished conduit modification, paragraph
5.
A cable
was not secured
in a cable tray as required,
a field
change notice was not incorporated into a work plan that was
closed,
and conduit covers were not installed although indicated
as completed in the work plan.
These
changes
occurred
about three
years
ago when unqualified cables
were replaced,
but has
gone
undetected until this time.
~,
Persons
Contacted
Licensee
Employees:
REPORT DETAILS
- 0. Zeringue,
Vice President
- R. Hachon,
Plant Manager
- J. Rupert,
Engineering
and Modifications Manager
- T. Shriver, Licensing
and guality Assurance
Manager
D. Nye, Recovery Manager
- E. Preston,
Operations
Manager
- J. Haddox,
Engineering
Manager
M. Bajestani,
Technical
Support
Manager
A. Sorrell, Chemistry
and Radiological Controls Manager
C. Crane,
Maintenance
Manager
+P. Salas,
Licensing Manager
- R. Wells, Compliance
Manager
J.
Corey, Radiological
Control Manager
J. Brazell, Site Security Manager
Other-licensee
employees
or contractors
contacted
included licensed
reactor operators,
auxiliary operators,
craftsmen,
technicians,
'and
public safety officers;
and quality assurance,
design,
and engineering
personnel.
NRC Personnel:
2.
P. Kellogg, Section Chief
- C. Patterson,
Senior Resident
Inspector
- J. Munday, Resident
Inspector
- R. Musser,
Resident
Inspector
G. Schnebli,
Resident
Inspector
L. Watson,
Project Engineer
- Attended exit interview
and initialisms used throughout this report are listed in the
last paragraph.
Surveillance Observation
(61726)
The inspectors
observed
and/or reviewed the performance of required SIs.
The inspections
included reviews of the SIs for technical
adequacy
and
conformance to TS, verification of test instrument calibration,
observations
of the conduct of testing,
confirmation of proper. removal
from service
and return to service of systems,
and reviews of test data.
The inspectors
also verified that
LCOs were met, testing
was
accomplished
by qualified personnel,
and the SIs were completed within
the required frequency.
The following SIs were reviewed-during this
reporting period:
a.
2-SI-4.7.A.3.b,
Suppression
Chamber
Reactor Building Vacuum
Breaker Cycling
b.
On October 22,
1993, the inspector
observed
the performance of 2-
SI-4.7.A.3.b,
Suppression
Chamber
Reactor Building Vacuum
Breaker Cycling.
This SI demonstrates
the operability of the two
Reactor Building to Suppression
Chamber
Vacuum Breakers
by cycling
the valves
(vacuum breakers)
and insuring that less force than the
maximum equivalent
dp specified in the
TS is utilized when
unseating
the valves.
In addition, the vacuum breakers
were
tested for freedom of motion as well as inspecting the internals
for debris
and foreign material.
Personnel
performing the testing
utilized a current revision of the SI and demonstrated
the proper
technique for independent verification.
No deficiencies
were
noted
by the inspector.
2-SI-4.5.B. I.d(II), quarterly
RHR System
Rated
Flow Test
Loop II
On October
29,
1993, the licensee
performed 2-SI-4.5.B.l.d(II),
quarterly
RHR System
Rated
Flow Test
Loop II as
a routine
surveillance required
by TS.
The surveillance
was completed
satisfactorily.
The inspector reviewed the completed
procedure
and verified the plant conditions were acceptable for performing
the test,
the acceptance
criteria were met, the test equipment
was
appropriate,
and the system
was returned to the standby lineup.
No deficiencies
were noted
by the inspector.
No violations or deviations
were identified in the Surveillance
Observation
area.
3.
Maintenance
Observation
(62703)
Plant maintenance activities were observed
and/or reviewed for selected
safety-related
systems
and components
to ascertain
that they were
conducted
in accordance
with requirements.
The following items were
considered
during these
reviews:
LCOs maintained,
use of approved
procedures,
functional testing and/or calibrations
were performed prior
to returning components
or systems
to service,
gC records maintained,
activities accomplished
by qualified personnel,
use of properly
certified parts
and materials,
proper
use of clearance
procedures,
and
implementation of radiological controls
as required.
Work documents
were reviewed to determine
the status of outstanding jobs
and to assure that priority was assigned
to safety-related
equipment
maintenance
which might affect plant safety.
The inspectors
observed
the following maintenance activity during this reporting period:
On November 9,
1993, the inspector
observed
maintenance activities
associated
with
WO 93-14450-00,
which was written to backfill the
reference
leg for the 2-LT-3-60,
an
A channel
instrument.
Operations
had previously identified that this instrument
was indicating,.
approximately
one inch higher than the instruments
in 8 channel.
The
inspector verified the prerequisites
were met and that the technicians
had the appropriate
approvals to begin work.
Operations
entered
the
applicable
LCOs and the reference
leg was backfilled without incident.
Following completion of the work, the instrument indicated approximately
one
and one-half inches lower than the
B channel.
Engineering stated
that this was expected
due to the difference in elevations
between the
condensing
pots.
The inspector will continue to follow activities in
this area.
No violations or deviations
were identified in the Maintenance
Observation
area.
Operational. Safety Verification (71707)
The
NRC inspectors
followed the overall plant status
and any significant
safety matters related to plant operations.
Daily discussions
were held
with plant management
and various
members of the plant operating staff.
The inspectors
made routine visits to the control rooms.
Inspection
observations
included instrument readings,
setpoints
and recordings,
status of operating
systems,
status
and alignments of emergency
standby
systems,
verification of onsite
and offsite power supplies,
emergency
power
sources
available for automatic operation,
the purpose of
temporary tags
on equipment controls
and switches,
alarm
status,
adherence
to procedures,
adherence
to LCOs, nuclear instruments
operability,
te'mporary alterations
in effect, daily journals
and logs,
stack monitor recorder traces,
and control
room manning.
This
inspection activity also included numerous
informal discussions
with-
operators
and supervisors.
General
plant tours were conducted.
Portions of the turbine buildings,
each reactor building,
and general
plant areas
were visited.
Observations
included valve position
and system alignment,
and
hanger conditions,
containment isolation alignments,
instrument
readings,
housekeeping,
power supply and breaker alignments,
radiation
and contaminated
area controls,
tag controls
on equipment,
work
activities in progress,
and radiological protection controls.
Informal
discussions
were held with selected
plant personnel
in their functional
areas
during these tours.
a ~
Unit Status
b.
Unit 2 operated
continuously during this period without any
significant problem.
The unit was on-line for 169 days at the end
of the period.
Unit 2/3 Separation
Clearances
The Unit 3 electrical distribution system currently has
operational restrictions required to allow operation of Unit 2.
The restrictions
are
a result of unresolved
engineering
concerns
involving Appendix R, station blackout,
equipment qualification,
or, electrical separation/isolation
capabilities.
These
restrictions
are controlled by clearances,
caution orders,
and
operating instructions.
They, in turn, reference
the electrical
distribution system one-line drawings which use notes to restrict
breaker closure.
The inspector reviewed portions of clearances
3-
91-095,
3-91-096,
0-91-353,
and 0-91-362 which were issued to
prevent Unit
1 and
3 components
from affecting Unit 2 operation.
These clearances
contain components restricted
by engineering
holds
and other components
tagged for convenience.
This could
include entire systems that are tagged which are currently not
needed,
rather than spending
resources
to identify portions of
systems that do need to be tagged.
Boundary isolation points
tagged
by these
clearances
may be untagged for a period not
exceeding forty-five days provided it is approved
by Technical
Support,
Operations,
and if an engineering
hold exists,
by Site
Engineering.
If the component
needs to be removed from the
'learance
for a period exceeding forty-five days,
the Unit
interface drawings depicting these
components
is to be revised to
indicate the new position.
During this inspection the inspector
noted
changes
to the clearance
boundary which exceeded this time
requirement.
This was discussed
with operations
management
and
the discrepancy
was adequately
resolved.
RWCU Appendix
R Safe
Shutdown
Procedure
Concerns
On October 28,
1993,
Engineering determined that
a calculation
used erroneous
cable routing information to determine the impact
of an Appendix
R fire on the
RWCU system.
The calculation
assumed
that the
RWCU system
was unaffected to the extent that the system
could be isolated
by one of two isolation valves in the event of
an Appendix
R fire.
However, it was not recognized that the
isolation capability was not available for fires occurring in fire
zone 2-4.and fire area
16. 'uring
a review of the calculation it
was discovered that the cables to the isolation valves traverse
these
areas
and therefore the system is not assured
of being able
to be isolated
as required.
As a result of this finding,
Engineering initiated
PER 93-0145.
On October 29,
1993, roving
fire watches
were established
in fire zone 2-4 and fire area
16,
as compensatory
measures
due to this condition.
On November 2,
1993, the inspector questioned
why the licensee
did not take
compensatory
measure
A for the two valves,
as described
in the
Appendix
R SSP.
Compensatory
measure
A required that action
be
taken in accordance
with the
TS referenced for that particular
component,
which in this case,
was to isolate the system
by
shutting the two affected valves within four hours.
Additionally
on November 2,
1993,
an Engineering
walkdown verified that the
cables for the two valves in fire zone 2-4 were located adjacent
to each other
and
as such could not be relied
on during
a fire in
this area.
On November
3,
1993, the Appendix
R SSP
was revised to
allow the option of taking compensatory
measure
A or
B for the
one-hundred-twelve
items previously requiring only compensatory
measure
A.
Compensatory
measure
B requires that the Appendix
R
function of the equipment
be restored
in seven
days or an
equivalent
shutdown capability be provided,
which is typically
satisfied
by establ.ishing
a fire watch in the affected
areas.
TS 6.8. 1. 1 requires that written procedures
shall
be established,
and maintained covering the fire protection program
implementation.
In addition, license condition
14 of the Unit 2
operating license states that changes to the fire protection
program can
be made without approval of the
NRC provided the
ability to achieve
and maintain safe
shutdown is not adversely
affected
by a fire.
The
SSP revision approved
on November 3,
1993,
changed
the fire protection program in such
a way as to
potentially adversely affect the ability of the plant to achieve
and maintain safe
shutdown, without first gaining prior approval
from the
NRC.
The licensee
indicated that additional
information
was being identified on this subject
and requested
a meeting to
discuss this information.
This item is unresolved
pending the
outcome of a meeting
on the subject
and is identified as
260/93-39-01.
In addition,
on November 4,
1993, the inspector
questioned
why the licensee
did not establish
a continuous fire
watch in the cable spreading
room of fire area
16 as required
by
the
SSP.
The licensee
stated that
a continuous fire watch should
be established
and corrected
the problem.
Drywell Control Air Dewpoint
Hoisture sensors
which provide
a control
room alarm upon sehsing
high moisture content in the drywell control air system
have
been
proven to be unreliable.
As a compensatory
measure,
TACF 2-93-01-
32 was written to facilitate the installation of a portable
dewpoint hygrometer
on the
2B control air receiver
tank to allow
periodic monitoring of the dewpoint temperature.
The safety
assessment
for all TACF states
that
upon receipt of the high
moisture alarm, Operations
personnel will valve in the dewpoint
hygrometer
and verify that
an acceptable
dewpoint is obtained.
The inspector questioned
two UOs and two ASOSs about the actions
to be taken
upon receipt of this alarm.
None of the operators
were aware that specific action needed to be taken in accordance
with the
TACF.
This weakness
was discussed
with operations
management
who felt it prudent to revise the
ARP to include the
appropriate
actions.
Unit Operator
Instrument
Checks
and Observations
While reviewing the Unit 2 unit operator
instrument checklist,
the
inspector noted that the main steam line flow, indicated
as
a dp
on ATUs, differed by as
much as nine psid between
steam lines.
Each
steam line has
one flow element which feeds four
transmitters.
The operator records
the dp from each
ATU and
compares
the values with the others.
When questioned
as to what
would be considered
an unacceptable
comparison,
the unit. operator
did not know.
He stated that there
was
no acceptance
criteria
assoc'i.ated
with the comparison.
This instrument
check,
performed
6
once per day to satisfy the requirements 'of TS 4.2.A, is defined
by. TS as
a qualitative determination of acceptable
operability by
observation of instrument behavior
and shall include
a comparison
with other instruments
measuring
the
same variable.
Operations
management
concluded that there
was
no requirement to define the
acceptance
criteria of an instrument
check in terms of allowable
differences
between
instruments
measuring
the
same parameter.
However, the licensee
plans
on collecting information from other
utilities concerning this and possibly revising their procedures
to better define acceptable
comparisons.
Pending resolution, this
item will be tracked
as IFI 260/93-39-02,
Acceptance Criteria For
Instrument
Comparison Surveillances.
REX System Failure
On November 2,
1993, the inspector experienced
problems with the
licensee's
REX system.
This system is
a computerized
exposure
tracking system for personnel
working under
a radiological work
permit.
The licensee
requires that personnel
have
a briefing on
the system
use prior to entry on
an
RWP.
In the morning, the
inspector entered
the
RCA on the general
access
RWP for a tour of
the reactor building.
After one hour, the inspector exited,
signing off the
RWP using the computer.
The inspector
noted that
the dose received
was zero although
one or more
HR was expected
after being in the reactor building for over an hour.
Later, in the afternoon the inspector
attempted to use the
REX
system
again for entry into the reactor building.
The computer
initially stated that entry was denied
and
a briefing was required
for entry.
A health physics technician assisted
the inspector
and
the computer indicated that
an exit entry had not been received.
The i'nspector questioned this
and noted several
rows of other
people
were in line waiting to enter the
RCA because
of similar
problems.
The inspector discussed
the systems's
apparent
problems
with a radiological controls supervisor.
Reliability of the
REX
system will be monitored
by the inspector.
Housekeeping
On November 2,
1993, during
a routine tour of the Unit 2 reactor
building the inspector
observed
several
large loose pieces of
insulation
on top of some
HVAC ducting.
The ducting was near the
overhead of this floor elevation but appeared
to be at location
for some time due to the collection of dust
and dirt around the
insulation.
On November 4,
1993, during
a routine tour of the Unit I and
2
diesel
generator
building the inspector noticed that the general
cleanliness
of the rooms
had deteriorated
somewhat.
The rooms are
normally clean.
The rooms were dusty
and
a large
number of spider
webs
had accumulated
in the area.
These
issues
were discussed
with plant management
on November
5,
1993.
Scram Reduction Efforts
On October
13,
1993, at-6:10 a.m., the Unit 2 Condensate
Demineralizer
System
bypassed
when returning demineralizer
H to
service.
This was apparently
caused
by the "E" valve on the "B"
demineralizer sticking closed
and then fully opening quickly at
the
same time the "H" demineralizer
was being placed in service.
The demineralizers
were restored to normal
and
no plant transients
were observed.
Work request
C232341
had
been previously submitted
on the "B" demineralizer for the failure of the "E" valve to
respond properly to its air signal.
The valve was subsequently
adjusted
and the work order closed out later that
same day.
Discussions with operations
personnel
indicated that had this
occurred in the past it might have resulted
in a plant
trip.
However,
due to the efforts of the Scram Frequency
Reduction
Team, modifications
had
been
accomplished
to this system
that reduced
the possibility of a trip for this event.
The
recommendation
made
by the
SFRT was to stagger
the
and the
CBPs low suction pressure trips such that all the RFP's did not
trip at the
same point'nd all the CBP's did not trip as the
same
point.
This was to be accomplished
by varying the setpoints
or
varying the time delays of the
pump trip circuitry.
By varying
one of these
parameters
a low pressure
pulse would not trip either
all the RFP's or all the CBP's.
Therefore,
loss of a single train
might allow pressure
to build back up to prevent -tripping the
other trains,
thus preventing
a loss of all feedwater.
This
modification was
implemented
by
DCN
W 16281A which was completed
in May 1991.
The inspectors
considered
the licensee's
efforts in
this area
commendable.
Cold Weather Preparation
The inspector
reviewed the licensee's
program for cold weather-
protection of equipment.
The licensee
has
an extensive
program
for identifying, establishing,
and repairing freeze protection
equipment
such
as heat tracing,
room heaters,
and space
heaters.
Operations
completed various valve,
and door
lineups for prevention of cold weather
damage.
Maintenance
has
the responsibility of testing the equipment
and if needed
performing repairs,
and were approximately
90 percent
complete.
The freeze protection for the fire protection equipment
was
complete.
The inspector walked down various outside
areas
subject
to cold weather
damage
and verified heat tracing was established,
heaters
were operable,
and temporary protection devices
such
as
canvas
or wood shelters,
were in place.
The inspector will
continue to monitor activities in this area
as repairs
on damaged
equipment is completed.
One unresolved
item and one inspector followup item was identified in
the Operational
Safety Verification area.
Design
Changes
and Plant Modifications (37700)
Program
Review
The inspector
reviewed
changes
to the plant design
change
and
modification process.
The licensee
has replaced
BP 205,
Issue
Management,
which described
the design
issue origination process,
with BP 312,
BFN Scope Control Process.
BP 312 establishes
the PID
process.
Any nuclear
power individual can initiate a PID.
Primary
responsibilities for initial review and tracking have
been divided
between the
SNM, the
ICPN,
and the Site Controller.
The
SNN is
responsible for tracking planning items, developing
a
BFN Long
Range
Plan
and preparing
a Fiscal
Year Project List.
The
ICPM
develops
scope of work and cost benefit information.
The Site
Controller performs resource
and funding estimates.
BP 312 also establishes
two review groups,
the
SMART and the
WCT.
The
SMART performs the review for all PIDs associated
with scope
changes
and emergent
work.
The
WCT performs the review for new
work.
The PID is reviewed
by the principal manager
and system engineer
then goes to the
SMART or
WCT for disposition.
BP 312 provides
guidance
on categorizing
and ranking the items
and defines the
managers
on the
SMART and
WCT.
The inspector reviewed the MIL of open
and closed
items
and the
inactive MIL.
Packages
of selected
NIL items which were
open
or
had
been placed
on the inactive list were reviewed to determine if
the licensee
had adequate justification for the disposition of the
.item, i.e., delaying implementation or canceling the project.
The
inspector
had
no questions
on disposition of the packages.
The inspector also reviewed portions of the following procedures
which define the design review process:
SSP 9.3, Plant Modifications and Design
Change Control,
Rev.
10
SSP 9.4, Configuration Management/Control,
Rev.
1
SSP 9.5,
Design Engineering,
Rev.
0
BFEP PI 89-06,
Design
Change Control,
Rev.
9
QDCN and
SCDN Processes
During October
1993 the licensee identified that
a containment
isolation valve had
been replaced with a valve of a different,.
design
and the Appendix J test method
had not been revised to test
for stem leakage.
This issue is discussed
in paragraph
S.d.
The
valve orientation
had
been questioned
via QDCN 23603A and the
Appendix J testing error was not identified in the
QDCN review.
The inspector reviewed the
QDCN process
described
in procedures
SSP 9.3 and
BFEP PI 89-06.
'The
QDCN is used to disposition
questions
and provide clarification of existing design output
documents
including DCNs.
The inspector selected
20 of the
75
QDCNs closed in April and Hay of 1993
(end of Unit 2 Cycle
6
refueling,outage) for review.
The inspector noted that in five of
the
QDCNs generated
by organizati.ons
other than Site Engineering,
including
QDCN 23603A, the review by the System Engineer
and the
Technical
Support Superintendent
had
been
marked
as not
applicable.
Site Standard
Practice,
Plant Hodifications
and
Design
Change Control,
Rev.
10, Section 3.2.2, requires that
QDCNs
that are not originated
by Site Engineering
be reviewed
by the
Technical
Support - System Engineer
and the Technical Support
System Engineering Supervisor.
The failure to route
QDCN 23603A
to Technical
Support for review contributed to the failure to
identify the inadequate
testing configuration for leak rate
testing of containment isolation valve 2-FCV-064-20.
Technical
Support provides Appendix J reviews.
In two of the cases
reviewed,
an
FDCN had
been
changed to a
QDCN.
In these
cases,
there
does not appear to be
a review of the need to send the
QDCNs
to Technical
Support for review.
The inspector reviewed
a sample of 20 of the
63
SCDNs generated
since October
1993.
SCDNs are
used to support documentation
changes
only.
A case
where
an
SDCN has
been
used to make
changes
in plant configuration
as discussed
in paragraph six.
The
inspector
reviewed the use of the selected
SDCN to confirm that
they were used'for documentation
changes
only.
The inspector also
sampled the documents that were changed to confirm that procedures
and drawings
had
been
updated.
No problems
were identified.
Fuses
On November 5,
1993, the inspector
compared electrical
fuse
labeling in the plant against electrical
equipment fuse tabulation
drawings.
These
are primary drawings maintained in the control
room.
Because of previous
concerns
and problems with fuse
labeling the licensee's
quality assurance
organization
conducted
an assessment
of fuse labeling Assessment
Report NQA-BF-93-154,
dated
November 2,
1993.
The assessment
team concluded that the
fuse labeling program was adequate
and effectively implemented.
The problem associated
with mislabeling of SBGT fuses
discussed
in
10
the licensee's
incident investigation,
II-B-93-034 was considered
isolated.
The inspector identified several
fuse
numbers that
had
been
changed
on drawing 2-45B721-50-10
under revision,4 dated
April 3,
1993, for
DCN S19592,
but the labeling had not been
changed
in the electrical
panel
next to the fuses.
This drawing
was
a primary drawing
and
a
CCD.
The following is
an example of
the labeling problems:
Fuse
UNID
Per Drawin
2-FU3-031-7206A
2-FU3-031'-7206B
2-FU3-031-7206C
'2-FU3-031-7207D
2-FU3-031-7208E
2-FU3-031-7209F
Fuse
As
abeled
2-FU3-031-4099B1
2-FU3-031-4099B2
2-FU3-031-4099B3
2-FU3-031-4099B4
2-FU3-031-4099B5
2-FU3-031-409986
The licensee initiated
a PER-930150 that identified an additional
six fuses with labeling different than the drawing.
The inspector
conducted
an independent
review of the
DCN S19592
and concluded that numerous other numbers
were changed
in addition
to fuse numbers.
The change
was to complete the
MEL safety system
project for system 31.
This consisted of EHS loading of the (-
list, Eg-list, I-Tabs,
Valve Tabs,
and
Fuse Tabs.
Ten pages of
fuses,
handswitches,
etc.,
were changed
by this S-DCN.
The inspector
checked
two switches listed
as being changed.
2-
XSW-31-4099A1 Appendix
R SDBR ACU NORM/ENER SM was changed to 2-
XSW-031-7205.
The inspector obtained
a copy of the system panel lineup checklist
and found the checklist
had not been
changed.
In addition, the
switches located in electrical
board
room
2B were checked
and they
were still labeled
as the checklist.
This was compared to
drawings in the control
room 2-45E2749-18
and 2-45E769-18 that
had
the
new numbers.
The inspector did not sample further but concluded that the
problem was not isolated to fuses.
The problem was with anything
changed
by the
S-DCN.
The
S-DCN that required changing of
numbering of components
on plant drawings
had not been coordinated
to have operations
or others to change plant labeling
and
procedures.
The inspector
concluded this is
a programmatic
problem with
engineering
changing drawings without adequate
coordination with
other plant organizations
to insure drawings accurately reflect
the plant configuration.
The licensee
has
done
an excellent job
in the past of issuing updated
drawings to reflect plant
modifications.
The drawings are issued prior to the system being
returned to service.
However, the reverse
has not been true.
Control
room drawings
have
been
changed to change
fuse number,
handswitch
number, etc., without the corresponding
changes
being
made in the plant or procedures.
According, this is the first example of the violation concerning
design. control.
Design control requirements
are established
by 10 CFR 50 Appendix
B Criterion III, Design Control.
This violation
will be identified as 259,
260, 296/93-39-03,
Failure to Control
Design Changes.
On November
16,
1993, the inspector discussed
these
issues with
the Engineering
and Modifications manager
and Engineering
manager.
Four systems
have
been completed for the
MEL safety system
project..
These
systems
were 18, 31,
63,
and 75.
The inspector
stressed
the importance of maintaining accurate
drawings to
reflect the plant configuration.
Containment Isolation Valve Improperly Installed
As discussed
in IR 259,
260, 296/93-36,
paragraph
4c, the licensee
discovered that CIV 2-FCV-64-20 was installed
such that its shaft
seals
were outside of the test boundary of its periodic type
C
LLRT.
Another issue related to this matter
was noted
by the
inspector during the review section 5.2.3.6
Venting and
Vacuum Relief) of the
FSAR.
This section contains
a
statement
that valves
2-FCV-64-20
and
21 (Inboard Primary
Containment Isolation Valves for the Reactor Building to Torus
Vacuum Breaker
Lines) are air-operated
and actuated
by a
differential pressure
signal that is independent of electrical
power.
However, the differential pressure
transmitters.
and
solenoid valves associated
with valves
2-FCV-64-20 and
21 are
. normally energized with electrical
power.
These matters
were
still under review at the conclusion of the last inspection period
and were tracked
as Unresolved
Item 260/93-36-01,
Containment
Isolation Valve Improperly Installed.
The licensee
concluded their review of this matter by completing
Incident Investigation II-B-93-041.
The inspectors
also completed
an independent
review of the issue.
The inspectors
have concluded
that the licensee failed to include
a
10 CFR 50 Appendix J review
in the design
process
which involved the installation of
containment isolation valves.
In not performing this review, the
licensee failed to recognize the importance of valve orientation
with regards to the
LLRT required
by TS 4.7.A.2.g.
Therefore,
the
valve (2-FCV-64-20)
was installed with its shaft seals
outside of
the test
boundary of it type
C LLRT.
One of the contributing
factors in this matter was the fact that
DCN g23608A was issued
without first being reviewed
by plant technical
support.
This
DCN
involved
a question
from the licensee's
maintenance
organization
regarding the importance of flow direction when installing CIVs 2-
12
FSV-64-17,
18,
19, 20,
and 21.
The
DCN g23608A was issued
by
plant engineering without considering
Appendix 3 testing of the
valve.
The issue of Technical
Support not reviewing g-DCNs as
required
by SSP-9.3 is further discussed
in paragraph
Sb of this
report.
During the inspectors'eview
of this issue,
the inspectors
determined that
a weakness
existed in the installation
instructions provided to the craft for the valves specified in DCN
W16880A (the original
DCN written to replace
2-FCV-64-17,
18,
19,
20,
and 21).
Simple sketches
on installation instructions
were
not included in the
DCN or WP. It appears
that
a great deal of
engineering
assistance
was required during the valves
installation.
In regards
to the inspectors
concerns that
Section 5.2.3.6 states
that valves
2-FCV-64-20 and
21 operate
independent
of electrical
power when in fact power is required to
normally operate
the valves,
the licensee is in the process
of
changing the applicable portion of FSAR Section 5.2.3.6.
The
proposed
change is as follows; one valve is air operated
and is
.,
actuated
by a differential pressure
signal;
upon loss of
electrical
power or air, the valve will fail in the open position.
This change satisfied the inspector's
concern in this area
as the
FSAR will more closely represent
actual plant conditions.
The licensee
has determined that valve 2-FCV-64-20 will be
reoriented
and tested during the next period of cold shutdown
providing the applicable
design documentation
is completed
and
materials
are available.
These
issues will continue to be tracked
= by URI 93-36-01,
pending resolution of the valve's orientation
and
testing.
Unfinished Modification
On November 2,
1993, during
a routine tour of the Unit 2 reactor
building the inspector identified some conduit that appeared
to be
an unfinished modification.
A modifications supervisor
was
contacted
and toured the area with the inspector.
On the
mezzanine
above the clean
room at the drywell entrance
there were
two conduits with missing inspection covers.
A single cable
was
in one of the conduits but the other conduit was empty.
Also, the
cable exited the conduit into a cable tray but the cable
was
dropped
down out of the cable tray.
The licensee
researched
the problem using the conduit numbers
and
found that
an
FDCN had not been incorporated into a
WP about three
years
ago.
The licensee
generated
PER
BF 930149 to resolve this
issue.
This will be tracked
as
URI 260/93-39-04,
Unfinished
Conduit Modification, pending resolution of the issue.
>f
0
~
~
13
'4f.
Reactor Water Level
Hodification'n
Hay 28,
1993, the
NRC issued Bulletin .93-03,
(Resolution of
Issues
Related to Reactor Vessel
Mater Level Instrumentation
in
BWRs), to all licensees 'operating
BWRs.
Specifically, the
bulletin deals with a generic
concern in which noncondensible
gases
could become dissolved in the reference
leg of BWR water
level instrumentation
and lead to
a false high level indication
after
a rapid depressurization
event.
In addition to several
short term compensatory
actions,
the bulletin requested
that each
licensee
implement hardware modifications necessary
to ensure
the
level instrumentation reliability for long-term operation.
This
hardware modification was to be implemented
by all licensees
in
the next cold shutdown period after July 30,
1993.
TVA responded
to the Bulletin with a letter dated July 30,
1993,
which stated that
TVA would install
a continuous fill system which
injects
CRD water to the water level instrumentation
condensing
chambers
through reference
leg piping.
Because
Browns Ferry Unit
2 has not been in a cold shutdown condition since starting
up from
the refueling outage in June
1993
and the fact that being in this
condition is
a requisite for installation of the continuous fill
system, the'odification is not yet implemented.
In preparation
of their first period of cold shutdown during the operating cycle,
the licensee
has prepared
and issued
DCN W16435C to document this
modification.
Currently, the licensee
is installing piping,
piping supports,
cabling
and conduit to the maximum extent
possible with the unit at power in order to minimize the effort
once .the unit has
reached
cold shutdown.
The licensee
anticipates
completing this work on November 23,
1993.
Once the unit reaches
cold shutdown,
current estimates
are that modification will
require
7$ days for implementation.
The inspectors
are currently
monitoring the "pre-outage"
work and anticipate monitoring the
final implementation of the modification.
One violation was identified in the design
change
area.
6.
Unit 3 Restart Activities
(30702,
37828,
61726,
62703,
71707)
The inspector
reviewed
and observed
the licensee's activities involved
with the Unit 3 restart.
This included reviews of procedures,
post-job
activities,
and completed field work; observation of pre-job field work,
in-progress field work,
and
QA/QC activities; attendance
at restart
.
craft level, progress
meetings,
restart
program meetings,
and management
meetings;
and periodic discussions
with both TVA and contractor
personnel,
skilled craftsmen,
supervisors,
managers
and executives.
a ~
Hodification of Unit Separation
Clearance
to Support Unit 3
Condenser
Hydrostatic Test
The return to service of systems
in support of Unit 3 condenser
hydrostatic test
and other activities required that
some breakers
14
be released
from an engineering
hold.
DCN S25756A revised
one-
line drawings
based
on calculations
which altered various
operational restrictions.
These restrictions
include such things
as Appendix R, station blackout,
equipment qualification,
and
electrical
cable separation/isolation
capabilities.
For example,
3B
CRD pump usage is restricted
due to a cable separation
violation and the
HPCI pump discharge
valve, 3-FCV-74-73, is
restricted
due to battery loading concerns.
The safety
assessment
for the
DCN states that the evaluation
concluded that certain
circuit breaker operating restrictions
must
be continued and/or
revised to support continued Unit 2 operation
and Unit 3 restart.
The
DCN specifically-'isted those
components
whose
use
was still
restricted.
On October
15,
1993, while verifying the proper
positioning of the components
on the list, the inspector
identified the foll'owing discrepancies:
1)
Breaker
602 on Battery Board
2 was being controlled by a
clearance
instead of a caution order.
2)
Breaker
601
on Battery Board
3 was found closed,
however it
was required to be open.
3)
Breaker
612
on Battery Board
3 was found closed
and being
controlled by a caution order,
however it was required to be
open.
After operations
management
was informed of these discrepancies
by
the inspector,
operations
personnel
walked down all of the
equipment affected
by an engineering
hold and found approximately
two pages of needed
changes
to the clearances,
caution orders,
and
Operating Instructions controlling these
components.
Discussion
with Operations
and Site Engineering
management
indicated that
these
changes
were inappropriately
made without the review of the
operations staff.
Criterion III of 10 CFR 50 Appendix B, requires
that measures
shall
be established
for the identification and
control of design interfaces
and for coordination
among
participating design organizations.
These
measures
shall include
the establishment
of procedures
among participating design
organizations for the review, approval,
release,
distribution,
and
revision of documents
involving design interfaces.
Failure to
coordinate
the issuance
of design
documents with the resulting
changes
in plant configuration is a violation of 10 CFR 50
Appendix B, Criterion III, Design Control,
and resulted
in
misconfiguration of the plant.
This will be identified as the
second
example of VIO 259,
260, 296/93-39-03,
Failure to Control
Design
Changes.
The inspector discussed
with site management
that close monitoring
of the unit separation
boundaries
was essential
as more Unit 3
systems
are tested
and returned to service.
15
b.
Design
Chan'ges
and Plant Modifications
The inspectors
review selected
Design
Change Notice packages
associated
with plant modifications to support the Unit 3 recovery
effort.
The
DCN work packages
were reviewed
and work in progress
was observed to:
ensure that the
DCN packages
were properly
reviewed
and approved
by the appropriate
organizations
in
accordance
with the licensees
administrative controls; verify the
adequacy of the
10 CFR 50.59 evaluations
performed
and that the
appropriate
FSAR revisions
were planned or completed, if
applicable;
ensure that the applicable plant operating
procedures
and design
documents
were identified and revised to reflect the
modification; verify that the modifications were reviewed
and
incorporated into the operations training program,
as applicable;.
verity that the modifications were installed in accordance
with
the work package (for those that could be physically inspected);
ensure that the modification was consistent with applicable
codes
and standards,
regulatory requirements,
and licensee
commitments;
and ensure that post modification testing requirements
were
specified
and that adequate
testing
was accomplished.
The
following DCNs were reviewed:
1)
DCN W17631,
Base Plate Installation
On October 21,
1993, during
a routine tour of the Unit 3
reactor building the inspector
observed
base plate
installation of supports.
This was being performed
under
DCN W17631.
The inspector
noted that four anchor bolts were
in place but the bolt holes were next to (about I/4 inch)
away from an existing hole.
The vacant holes were grouted
over but the sleeve
was still in place.
This in effect
appeared
to negate
the grouting since the spacing
between
the sleeves
was still below minimum spacing.
The inspector
contacted
a gA supervisor to review the installation.
In
addition the inspector reviewed
HAI 5.1 that specified the
spacing
between
anchor bolts.
Host distances
required
several
inches
between
spacing.
Initial review of this
issue
determined that
F-DCN 26899
was issued to revise
anchor bolt spacing
dimensions
because
of spacing
violations.
A different type anchor bolt penetrating
several
inches into the floor was used.
This design
strengthened
the area to be pulled out.
Additionally,
calculation
CD-f3064-922915
was revised to incorporate
the
F-DCN 26899.
The inspector reviewed the calculation
and
concluded the issue
was resolved.
2)
DCN W7731A, Electrical Separation
The inspector
reviewed the work associated
with scaffolding
in the Unit 2 reactor building spaces.
The work was being
performed under
DCN W7731A to reroute the normal
power
supply cable to 250 volt reactor
HOV Board
3C to correct
16
electrical
separation
concerns.
The cable
was
a safety
system cable but was routed in non-safety
raceways.
This
was
a Unit 3
DCN but involved work. in Unit 2 operating
spaces.
The inspector reviewed the safety
assessment
for
the
DCN and unit separ ation issues
were addressed.
TS
requirements',
secondary
containment,
and system operability
were each discussed.
Additionally, inspection of the
scaffolding in Unit 2 reactor building identified no
deficiencies.
The inspector concluded that the licensee
had
performed
a thorough
assessment
of this modification's
impact on the operating unit.
System
SPOC's
The purpose of SPOC process
is to provide
a systematic
method for
evaluating
items
and issues
which potentially affect the ability
of Unit 3 systems
and the Unit 3 portion of common
systems
to
perform as designed.
This process
determines
the status of each
item/issue
and assures
completion of those which affect system
return to operation for Unit 3 restart.
For each
system
evaluated,
the
SPOC process
may be accomplished
in two phases.
Phase
I SPOC addresses
the Restart
Test Program testing milestone
if that milestone exists for the system,
and establishes
system
status
control
by the Operations
department.
Phase II SPOC
addresses
System Return to Operation in preparation for the
declaration of system operability.
Each
phase
ensures
that open
items/issues
which potentially affect the phase
are either
completed,
or reviewed
and satisfactorily dispositioned.
The
process
does not declare
system operability.
Rather, it is used
to support
a declaration of system operability which is made after
other requirements for operability are satisfied (e.g.,
support
systems
available;
performance of Surveillance Instructions,
etc.).
The following system
SPOC packages
were reviewed to ensure
they
complied with SSP 12.55, Unit 3 System Pre-Operability Checklist,
Revision 5.
Hinor deficiencies
were resolved with the system
engineer.
System 27,
Condenser
Phase I.
System Testing
On November 8,
1993, the licensee
performed
a static hydrostatic
test
on the condensate
side of the main condensers.
The test
was
conducted
in accordance
with SOI-19, Flooding Hotwell for
Condenser
Tube
Leak Check.
There were no major problems
encountered;
however,
the test did identify that two condenser
tubes required plugging, seventy tubes required rerolling,
and
four tube sheet
holes required plugging because
the internal
baffle plates didn't allow for tube installation.
This was the
17
first milestone in the licensee's
efforts to return Unit 3 to
service
and it was accomplished
seven
days
ahead of schedule.
Reportable
Occurrences
(92700)
The
LERs listed below were reviewed to determine if the information
provided met
NRC requirements.
The determinations
included the
verification of compliance with TS and regulatory requirements,
and
addressed
the adequacy of the event description,
the corrective actions
taken,
the existence
of- potential generic problems,
compliance with
reporting requirements,
and the relative safety significance of each
event.
Additional in-plant reviews
and discussions
with plant
personnel,
as appropriate,
were conducted.
(CLOSED)
LER 50-296/92-006,
Inadvertent
Emergency Diesel
Generator Start
During Testing
Due To A Short Circuit.
On December 3,
1992, during the performance of the
3D
DG redundant start
test,
the
3D
DG inadvertently started
when test leads
connected
across
the autostart relay shorted.
The short occurred
when the test lead
was
pinched under
a movable handle
on the test equipment cart
and
damaged.
As corrective action the licensee
replaced
the .damaged test leads
and
secured
them in such
a fashion to reduce the potential for damage.
The
'oveable
handles
on the carts
were also removed.
Additionally, training
was provided to maintenance
personnel
on the impact of potential
degradation
of test leads.
The inspector
reviewed the training records
of the maintenance
personnel
and verified the test carts
were modified
to reduce the potential for damage to the test leads.
The inspector
considers this item closed.
Action on Previous
Inspection Findings
(92701,
92702)
a.
.
(CLOSED) Fire Protection
Weakness
Identified in IR 93-19
A weakness
was previously identified in IR 93-19 involving the
control
and timely update
requirements
of the licensee's
FPR and
the
LCO determinations for fire protection features
impacted
by
recent design
changes.
The licensee
issued
Revision
6 on
September
30,
1993, to SSP
12. 15, Fire Protection,
addr essing this
weakness.
The revision added Appendix A, Management of the Fire
- Protection
Report Volume 1, providing administrative controls for
the purpose of maintaining
and controlling the
FPR including
revising
and updating the document.
Step 5.0 of this appendix
assigns responsibility to site engineering requiring that the
be updated within 30 days after completion of a refueling outage
or earlier if deemed
necessary.
The residents
reviewed the
licensee's
corrective actions for this concern
and discussed
them
with the regional
based
inspector
and determined this issue
closed.
18
b.
(CLOSED)
URI 259,
260; 296/93-02-02,
Mislabeling of Fuses
(CLOSED)
URI 259,
260, 296/93-08-01,
Design Control Coordination
Discrepancies
(CLOSED)
URI 259,
260, 296/93-25-03,
SBGT Due to Fuse
Mislabeling
These
issues
are considered
closed with the issuance
of violation
259,
260,
296/93-39-03,
Failure to Control
Design
Changes.
This
violation encompasses
fuse labeling issues.
Site Organization
On November
10,
1993,
Eugene
Preston
reported
on site
as the Operations
Manager to fill the vacancy left by the resignation of Max Herrell.
On November
15,
1993,
Richard
Machon reported
on site
as the Plant
Manager replacing
John Scalice
who transferred
to Watts
Bar
as the
Operations
Vice President.
Independent
Safety Engineering
Group (40500)
The inspector
reviewed the status of the site's
ISEG.
The requirement
for an
ISEG was
a commitment under the Nuclear Performance
Plan
(Volume 3) for the restart of Browns Ferry.
The group was established
by
NUREG 0737 guidelines for multi-site utilities.
The group is
patterned after the Sequoyah plant that has the
ISEG requirement
in TS.
It is not
a TS requirement
at
BFNP.
On April 8,
1993, the licensee
submitted revision three of their N(A
plan that combined the site licensing
and quality manager into one
position.
This also placed the
ISEG under the licensing
and quality
manager on-site instead of an off-site corporate
manager.
Region II
accepted
the changes
on June
9,
1993.
The licensee
contends that the
site licensing
and quality manager
does not report to any site manager
and the independence
is maintained.
Further changes
are occurring with ISEG.
The group functions are being
incorporated into a new group called Reactor Safety Engineering
and
Review commonly called
RSER.
A procedure for this group is being
developed.
Exit Interview (30703)
The inspection
scope
and findings were summarized
on November
19,
1993,
with those
persons
indicated in paragraph
one above.
The inspectors
described
the areas
inspected
and discussed
in detail the inspection
findings listed below.
The licensee did not identify as proprietary
any
of the material
provided to or reviewed
by the inspectors
during this
inspection.
19
The Site V.P. stated that
a fire watch provided immediate detection of a
fire and the changes
to the plan,
as outlined in paragraph
4 above,
were
justified.
Item Number
Descri tion and Reference
260/93-39-01
260/93-39-02
259,
260,
296/93-39-03
URI, Inadequate
Safe
Shutdown
Procedure
Revision,
paragraph 4.c.
IFI, Acceptance Criteria For Instrument
Comparison Surveillances,
paragraph
4.e.
VIO, Inadequate
Design Control, paragraph
5.c and 6.a.
260/93-39-04
and Initialisms
URI, Unfinished Conduit Modification,
paragraph
5.e.
Licensee
management
was informed that
1
LER and
3 URIs were closed.
ASOS
ATU
BFEP
BFNP
BP
CCD
CFR
DCN
DP
EMS
FDCN
ICPM
IR
ISEG
LCO
LER
MAI
MEL-
Annunciator Response
Procedure
Assistant Shift Operations
Supervisor
Analog Trip Units
Browns Ferry Engineering Project
Browns Ferry Nuclear
Power Plant
Business
Practice
Condensate
Booster
Pump
Configuration Control Drawing
Code of Federal
Regulations
Containment Isolation Valve
Design
Change Notice
Diesel
Generator
Differential Pressure
Emergency Diesel
Generator
Equi'pment
Management
System
Flow Control Valve
Field Design
Change Notice
Fire Protection
Report
Final Safety Analysis Report
High Pressure
Coolant Injection
Heating, Ventilation,
8 Air Conditioning
Item Coordinator Project Manager
Inspection
Report
Independent
Safety Engineering
Group
Limiting Condition for Operation
Licensee
Event Report
Local
Leak Rate Testing
Hodification Alteration Instruction
Master Equipment List
HIL
HOV
NRC
PER
PSID
gA
gC
RSER
SFRT
SHH
SOI
SPAE
SSP
TACF
TS
UO
WP
20
Master
Issues List
Motor Operated
Valve
Nuclear Regulatory
Commission.
Problem Evaluation Report
Project Instruction
Planning
Item Description
Pounds
Per Square
Inch Differential
guality Assurance
guality Control
Reactor
Pump
Residual
Heat
Removal
Reactor-'Safety
Engineering
and Review
Radiological
Work Permit
Standby
Gas Treatment
System
Scram Frequency
Reduction
Team
Surveillance Instruction
Scheduling
Methods Manager
Special
Operating Instruction
System Plant Acceptance
Evaluation
System Pre-Operability Checklist
Site Standard
Practice
Safe
Shutdown
Procedure
Temporary Alteration Control
Form
Technical Specification
Unit Operator
Unresolved
Item
Violation
Work Control
Team
Work Order
Work Permit
0